Investment in Canada’s Oil Sands Declines, But Production Still Poised to Grow

Upstream investment in new projects in Canada’s oil sands has declined by two-thirds since the oil market downturn in 2014, falling to just $10 billion in 2017, according to IHS Markit, and there is no guarantee spending will rebound. The future of new oil sands projects is uncertain, in large part because of the mixed outlook for oil prices. Moreover, bringing a new oil sands project online is costly, requiring massive upfront investment and several years of development.

Canada’s oil industry could maintain output at current levels for many years to come even with only a limited number of new projects.

In the near term, Canada’s oil industry faces a variety of significant challenges, including midstream bottlenecks, steep discounts for its crudes, and carbon pricing. However, unlike shale drilling, for instance, oil sands projects have stable production profiles that span decades. This means Canada’s oil industry could maintain output at current levels, or see production grow, even with only a limited number of new projects.

Oil sands hit by price downturn

One of defining features of the collapse of prices for the oil industry has been an increasing focus on shorter-cycle projects at the expense of long-lived, costly megaprojects. Even the oil majors, which have expertise in developing large-scale offshore projects, are increasingly pivoting into shale drilling. ExxonMobil just laid out plans to triple its oil and gas production from the Permian by 2025, an announcement that comes one year after it spent $6 billion to acquire acreage in the prolific shale basin.

The increasing focus on short-cycle investments led to an exodus from Canada’s oil sands industry.

The increasing focus on short-cycle investments led to an exodus from Canada’s oil sands industry. Investment in new oil sands projects fell from $30 billion in 2014 to just $10 billion in 2017, according to a new report from IHS Markit. Some new oil sands mining projects have breakeven prices of $70 per barrel, which is arguably high for even the long run. Steam-assisted gravity drainage (SAGD) projects offer lower costs, but given the uncertainty regarding the direction of oil prices in 2018, let alone decades from now, it is no surprise that investment in new projects has fallen sharply.

The lack of investment raises questions about long-term production growth in Canada. Oil sands developers have been working through the queue of projects, but there are very few new projects receiving final investment decisions (FIDs). In a recent example, Suncor Energy announced the startup of its Fort Hills oil sands project, which will gradually ramp up to 90 percent of the project’s 194,000 b/d capacity by the end of 2018. Suncor and its partners gave the greenlight to Fort Hills back in 2013, and it is believed to be the last major oil sands project to be developed for the foreseeable future.

Near-term obstacles

In addition to price uncertainty, Canada’s oil industry faces a series of unique challenges that could deter upstream investment. The most obvious is the midstream bottleneck, which has worsened over time. The inability to bring a major pipeline on line has brought about steep discounts in Canadian oil benchmarks. The three major pipelines on the drawing board—Keystone XL, the Trans Mountain Expansion, and the Line 3 replacement—all face resistance and regulatory hurdles, and none will likely be completed before 2020. Western Canada Select, a benchmark that tracks heavy oil from Canada, is trading at a steep discount to WTI, a differential that has surged as high as $30 per barrel. The inauguration of the Fort Hills project will add to the midstream problems building up in Canada. Crude-by-rail shipments are expected to rise, but rail companies are unwilling to make the investments in capacity additions needed to ease the backlog. As a result, the large WCS discount is set to stick around for some time.

The three major pipelines on the drawing board all face resistance and regulatory hurdles, and none will likely be completed before 2020.

Another obstacle for Canada’s oil sands is carbon pricing. Alberta producers face an escalating carbon tax plus a cap on greenhouse gas emissions. IHS Markit estimates that the carbon prices “have not materially altered the economics for most oil sands production,” but carbon-intensive operations will be affected over time. Canada is one of the few major oil-producing regions in the world with carbon pricing, which “adds an additional layer of complexity and risk that is not yet present in most other oil-producing jurisdictions,” IHS Markit wrote in its report.

Oil sands production stable

Despite the decline in new investment, Canada’s oil sands production has actually increased by 500,000 barrels per day (b/d) since the market downturn began, and it could expand by an additional 700,000 b/d by 2020, according to IHS Markit. Much of those increases came from projects that were given FIDs before prices fell in 2014.

The production growth does not mean that Canadian oil producers avoided serious pain during the price decline. Far from it. When WTI bottomed out in early 2016 at below $30 per barrel, many oil sands producers were losing money on every barrel produced.

However, because of the production profiles of oil sands projects, output levels were not affected. Oil sands exhibit stable production for as long as 30 years or more, and thus operations tend not to be affected by short-term price volatility.

Unsurprisingly, new investment will depend on oil prices. In its base case scenario, IHS Markit assumes a gradual increase in prices over the next decade, and Canada’s oil sands industry holds off on new greenfield projects until the early 2020s. But since existing projects will not see declines, even a modest increase in spending translates into production gains.

Even in a low price scenario that sees upstream investment fall sharply, production from Canada’s oil sands does not. Output remains stable and companies would chip away at costs over time, experiencing more production gains by upgrading existing facilities. This scenario is a reminder about the unique nature of Canada’s oil sands. “The absence of meaningful [production] declines makes a future without oil sands growth difficult to see,” IHS Markit concluded.

Long-term supplier for U.S.

Ultimately, IHS Markit does not see upstream investment in Canada’s oil sands returning to pre-2014 levels in any of its scenarios, but it also does not see production falling. Production will rise by somewhere between 700,000 b/d and 1.4 million barrels per day through 2030.

Canada’s oil sands will supply U.S. refiners in the Midwest and Gulf Coast for decades to come.

The upshot is that Canada will remain a supplier for U.S. refineries for the long term. There are questions about the long-term viability of U.S. shale, with the IEA predicting a peak and decline beginning in the mid-2020s. Canada’s oil sands, on the other hand, will supply U.S. refiners in the Midwest and Gulf Coast for decades to come.

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The Fuse is an energy news and analysis site supported by Securing America’s Future Energy. The views expressed here are those of individual contributors and do not necessarily represent the views of the organization.

Issues in Focus

Safety Standards for Crude-By-Rail Shipments

A series of accidents in North America in recent years have raised concerns regarding rail shipments of crude oil. Fatal accidents in Lynchburg, Virginia, Lac-Megantic, Quebec, Fayette County, West Virginia, and (most recently) Culbertson, Montana have prompted public outcry and regulatory scrutiny.

2014 saw an all-time record of 144 oil train incidents in the U.S.—up from just one in 2009—causing a total of more than $7 million in damage.

The spate of crude-by-rail accidents has emerged from the confluence of three factors. First is the massive increase in oil movements by rail, which has increased more than three-fold since 2010. Second is the inadequate safety features of DOT-111 cars, particularly those constructed prior to 2011, which account for roughly 70 percent of tank cars on U.S. railroads. Third is the high volatility of oil produced from the Bakken and other shale formations, which makes this crude more prone towards combustion.

Of these three, rail car safety standards is the factor over which regulators can exert the most control. After months of regulatory review, on May 1, 2015, the White House and the Department of Transportation unveiled the new safety standards. The announcement also coincided with new tank car standards in Canada—a critical move, since many crude by rail shipments cross the U.S.-Canadian border. In the words DOT, the new rule:

Since the rule was announced, Republicans in Congress sought to roll back the provision calling for an advanced breaking system, following concerns from the rail industry that such an upgrade would be unnecessary and could cost billions of dollars. The advanced braking systems are required to be in place by 2021.

Democrats in Congress have argued that the new rules are insufficient to mitigate the danger. Senator Maria Cantwell (D-WA) and Senator Tammy Baldwin (D-WI) both issued statements arguing that the rules were insufficient and the timelines for safety improvements were too long.

The current industry standard car, the CPC-1232, came into usage in October 2011. These cars have half inch thick shells (marginally thicker than the DOT-111 7/16 inch shells) and advanced valves that are more resilient in the event of an accident. However, these newer cars were involved in the derailments and explosions in Virginia and West Virginia within the past year, raising questions about the validity of replacing only the DOT-111s manufactured before 2011.

Before the rule was finalized, early reports indicated that the rule submitted to the White House by the Department of Transportation has proposed a two-stage phase-out of the current fleet of railcars, focusing first on the pre-2011 cars, then the current standard CPC-1232 cars. In the final rule, DOT mandated a more aggressive timeline for retrofitting the CPC-1232 cars, imposing a deadline of April 1, 2020 for non-jacketed cars.

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DataSpotlight

The recent oil production boom in the United States, while astounding, has created a misleading narrative that the United States is no longer dependent on oil imports. Reports of surging domestic production, calls for relaxation of the crude oil export ban, labels of “Saudi America,” and the recent collapse in oil prices have created a perception that the United States has more oil than it knows what to do with.

This view is misguided. While some forecasts project that the United States could become a self-sufficient oil producer within the next decade, this remains a distant prospect. According to the April 2015 Short Term Energy Outlook, total U.S. crude oil production averaged an estimated 9.3 million barrels per day in March, while total oil demand in the country is over 19 million barrels per day.

This graphic helps illustrate the regional variations in crude oil supply and demand. North America, Europe, and Asia all run significant production deficits, with the Middle East, Africa, Latin America, and Former Soviet Union are global engines of crude oil supply.